This invention is in the field of hydrocarbon (i.e., oil and gas) production. Embodiments of this invention are more specifically directed to the analysis of hydrocarbons produced from each of multiple formations exploited by a common well.
It is commonplace, in modern production fields, for individual wells to produce hydrocarbons (i.e., oil and natural gas) from multiple formations in the earth, by way of perforations in the wellbore at various depths along its length. Knowledge of the hydrocarbon output produced from each of these multiple formations is extremely useful information in managing individual wells, and in managing the exploitation of the reservoir as a whole. In addition, in some locations, regulations require the allocation of production to individual formations for the payment of royalties. Typically, only the commingled flow rate from of the formations produced by the well is available, because there is often no economically practical way to directly measure the production from the individual formations. This difficulty is especially true in those formations referred to in the art as “tight gas formations”, in which the gas-bearing strata are not well-defined, and in which open hole production techniques are used (with all perforations open along the producing length of the wellbore).
As such, sampled measurement of the output of the individual formations is the usual basis for allocating the commingled flow among the individual producing formations. A typical conventional approach to this allocation involves limiting the produced oil and gas to that from a single one of the formations along the wellbore, in isolation from the other formations, for example by inserting packers along the wellbore. Once isolated, any flow to the surface from that formation is measured. The formation is then stimulated and the flow from the isolated formation is then measured over a period of hours (e.g., eight to twelve hours) directly after that stimulation. This flow will be at a higher pressure than under normal producing conditions, which enables the analyst to estimate a flow versus pressure characteristic for the formation. These measurements are repeated for each of the formations into which the wellbore extends, in isolation from the other formations. One can then estimate the allocation from each of the multiple formations, for a measured commingled flow rate, from a combination of these estimated characteristics.
However, this conventional method has several disadvantages. One significant disadvantage is that the allocation measurement is not made under the actual flow conditions of production into a pipeline. As such, the effects of pipeline backpressure, and of differences in the flow path presented by production and pipeline tubing, are not included in the measurement and estimation. In addition, this measurement and allocation method is typically only performed once during the life of the well, because of the high cost of performing the test, including the loss of production. Changes in production from the various formations over time are thus not considered in this conventional allocation technique. In other words, error is inherently present in the original flow rate allocation, and this error is not only maintained over the life of the well cascades to other calculations for the well.
Another conventional approach to allocation of production among multiple formations is to measure the oil and gas flow for an extended period, such as thirty days, after the well has been completed to the depth of each formation. By way of subtraction of each formation's contribution as the next stage of the well is completed, one can arrive at an estimate of the relative contributions of each formation to the commingled flow. However, this approach is also subject to substantial error, considering that the pressure at which the earlier measurements are made can change as the well is completed at additional formations. In addition, this measurement approach is also performed only at the initial completion of the well, and as such cannot comprehend changes in production over time.
Differences in the compositional attributes of gas produced from different formations are observable. One such gas composition attribute that can differ among formations is the concentration of heavy isotopes of carbon and hydrogen in the gas itself. For example, the ratios of heavy carbon 13C to stable carbon 12C, and of heavy hydrogen 2H (or deuterium, D) to stable hydrogen 1H, in each of several gas components (methane, ethane, propane, isobutane, n-butane, etc.), depend on the manner and era in which the gas was formed, and thus from formation to formation. These isotopic concentration ratios are measurable to a high degree of accuracy, by conventional equipment.
Accordingly, the allocation of production between two formations that produce through the same well, using isotopic concentration ratios, is known in the art. In a conventional approach, the isotopic concentration ratios in one or more gas components are measured from each of the two formations, individually. Endpoints of a “mixing curve” between the two formations are derived from the measured elemental isotope ratio (e.g., 13C to 12C) for a gas component (e.g., ethane, or “C2”) for the two cases of 100% production from each of the formations. Either by assuming a linear relationship between these endpoints, or by otherwise deriving a function between these endpoints, a mixing curve of the production percentage from one of the formations as a function of measured commingled isotopic concentration ratio can be derived. One can obtain the relative allocation of gas production from the two formations based on samples of the commingled production gas. This conventional allocation method can also be used for allocating oil production, as the isotopic concentrations of natural gas entrained in the oil output can be analyzed in this manner.
However, it has been observed, according to this invention, that a given formation can have various producing regions, at different depths, and that these producing regions can exhibit isotopic concentrations that vary significantly among one another. For such formations, conventional isotopic allocation methods have been observed to involve significant error, because of the spread of the values of isotopic concentration within the formation.
In addition, this simple method does not work in the case of commingled flow from more than two formations, because it does not yield a unique allocation result from the measured isotope ratio of the commingled flow from three or more formations.